Integrated gasification combined cycle (IGCC) power generation systems are used throughout the world to generate power from the gasification of a fuel source. In such systems, a raw synthesis gas (or syngas) fuel gas stream, comprising H2, CO, CO2, and H2O, is produced by the partial oxidation reaction of a hydrocarbonaceous fuel with a free-oxygen containing gas, typically in the presence of a temperature moderator such as steam, in a quench gasification reactor.
The syngas produced is cooled by quenching in water to produce a stream of quenched saturated syngas at a temperature typically in the range of about 450xc2x0 F. to 550xc2x0 F. and typically at a pressure of about 700 to 1500 psia. A more detailed description of one such process appears in U.S. Pat. No. 5,345,756.
The syngas produced is then generally cooled to a temperature of 40xc2x0 F. to 140xc2x0 F. and purified in an acid gas removal unit employing a physical or chemical solvent to remove H2S and COS from the syngas stream. The purified syngas is mixed with a diluent gas, such as nitrogen gas or water vapor, and then fed to the combustor of a gas turbine for power production. The mass flow of the diluent gas helps to increase the power generation and reduce NOx gasses produced by the combustion of the syngas in the gas turbine combustor. It is desirable in prior art IGCC processes to superheat the syngas/diluent mixture to its maximum attainable temperature, usually between 350xc2x0 F. and 1000xc2x0 F., prior to being introduced into the gas turbine combustor. This heating is commonly done with high or low pressure steam. The thermal energy introduced to the syngas/diluent mixture through superheating is combined with the chemical energy released by the syngas upon combustion. The hot gasses from the combustion are sent to an expander/generator that converts the energy released from the gas into electricity.
An air and nitrogen integrated IGCC system is usually preferred because of the potential for operation at maximum overall efficiency. Air is compressed in a gas turbine air compressor, usually located along the same shaft as the aforementioned combustion gas expander. A portion of compressed air is combusted with the syngas in the gas turbine combustor. The remaining portion, the extracted air, is cooled against the gas turbine diluent stream and fed to an air separation unit (ASU) that provides oxygen to the gasification step and nitrogen as diluent to the gas turbine.
Finally, waste heat from the gas turbine is then commonly used to produce steam, usually in a heat recovery steam generator (HRSG). The produced steam is commonly used as the temperature moderator in the gasification unit or to superheat the syngas/diluent feed stream to the gas turbine, with the balance of the steam generally used in a steam turbine for further power production. Various modifications on this general prior art process can be found in U.S. Pat. Nos. 5,715,671, 5,345,756, 5,117,623 and 5,078,752.
As stated, prior art IGCC processes find it desirable to heat the syngas/diluent to its maximum sustainable temperature prior to combustion in the gas turbine. For example, in U.S. Pat. No. 5,715,671, the syngas is heated to 390xc2x0 C. (734xc2x0 F.) before being passed to the gas turbine. In U.S. Pat. No. 5,345,756, the syngas is treated to a temperature in the range of about 350xc2x0 F. (177xc2x0 C.) to 1000xc2x0 F. (538xc2x0 C.) prior to entering the combustor. U.S. Pat. No. 5,117,623 prefers the syngas to be heated to 200xc2x0 C. (392xc2x0 F.). Finally, U.S. Pat. No. 5,078,752 contemplates syngas temperatures of 1,800xc2x0 F. to 1,900xc2x0 F., and possibly temperatures between 2,000xc2x0 F. and 2,300xc2x0 F.
Often times, the syngas heating is done with steam. The steam used to heat the syngas is thus not available to the steam turbine for additional power production. Furthermore, during high ambient temperature conditions it is sometimes desirable to add additional steam injection to, the syngas to obtain a higher power output from the combustion turbine. However, the additional steam injection unacceptably lowers flame stability. It is economically important to maximize electrical generating capacity at high ambient conditions since the price of power at high ambient temperatures can be up to 100 times that at low ambient temperatures. Thus, it would be desirable to develop an IGCC process wherein the cooler syngas is used in the combustor of the gas turbine, and not preheated with steam, so :hat more steam is available for power generation in the steam turbine.
The present invention is directed toward a process wherein the syngas and diluent gas is heated to about 100xc2x0 F. to 200xc2x0 F. above its dew point, a maximum temperature of about 350xc2x0 F. (177xc2x0 C.). Additional fuel with a high heating value, such as natural gas, is added to the syngas to increase the total heating value of the feed to the combustor of the gas turbine. Because of the lower temperature of the syngas/diluent feed stream, the natural gas and diluent flowrates are increased to maintain the power output of the gas turbine. Although the addition of the diluent is necessary to reduce harmful NOx gasses produced in the combustor, it also decreases the flame stability of the combustor. The addition of the natural gas is used to elevate the heating value, keeping the flame in the combustor stable, so that the additional diluent gas can still be injected into the syngas.
Because the syngas/diluent feed stream is not heated to the high temperatures disclosed in the prior art, the excess steam that would otherwise heat the feed stream is available for power generation in the steam turbine, increasing its individual power output and the overall power output of the IGCC process.
Another objective of the present invention provides an alternative use for the extracted air. Nitrogen from the air separation unit, used as the diluent stream, is usually supplied at about 280xc2x0 F. (138xc2x0 C.), and is usually heated to the same temperature as the syngas feed to the gas turbine combustor. Usually, this is in the temperature range of 350xc2x0 F. (177xc2x0 C.) to 1000xc2x0 F. (538xc2x0 C.) or greater. In the present invention, the diluent stream only needs to be heated to 100xc2x0 F. to 200xc2x0 F. above its dew point, or a maximum temperature of about 350xc2x0 F. (177xc2x0 C.). Because most of the heat from the extracted air will not be used to heat the gas turbine diluent stream, the heat can be used to produce low to medium pressure steam. This additional steam generation can be used in the gasification unit, allowing for more steam from the HRSG to be used for power generation in the steam turbine.
Because of the increased power production in the steam turbines, the total IGCC power production can be increased from 5-10%.